Gas turbine engines typically include a compressor section, a combustor section and at least one turbine that rotates in order to generate electrical power. The compressor discharge feeds directly into the combustor section where hydrocarbon fuel is injected, mixed and burned. The combustion gases are then channeled into and through one or more stages of the turbine which extracts rotational energy from the combustion gases.
In order to achieve maximum operating efficiency, gas turbine combustion systems must operate over a wide range of different fuel compositions, pressures, temperatures and fuel/air ratio conditions, preferably with the ability to use either liquid or gas fuels or a combination of both (referred to as “dual fire” systems). However, many candidate hydrocarbon fuels for use in gas turbine combustors contain unwanted contaminants and/or byproducts of other processes that tend to inhibit combustion and/or reduce the capacity and efficiency of the gas turbine system. Many candidate fuels also create environmental pollution control issues, particularly the formation of undesirable NOx components.
As a result, various prior combustor designs have attempted, with only limited success, to maintain high gas turbine engine performance levels using liquid fuel compositions while achieving acceptable emission levels, particularly the amounts of NOx and CO resulting from combustion. Most gas turbine combustors capable of achieving low NOx emissions (referred to as “dry low NOx” (DLN)) require a lean, premixed combustion mixture comprising lower weight hydrocarbon fuel and an excess amount of air in order to control and limit NOx production. Typically, such combustors use a mixture of compressed natural gas consisting of 90-98% by volume methane (CH4) with lesser amounts of CO2, O2, N2 and a small fraction of short chain hydrocarbons such as ethane, ethylene, and acetylene. Those leaner mixtures tend to burn at a lower temperature than conventional diffusion flame combustors, thereby producing lower levels of pollutants, including oxides of nitrogen.
Many attempts have been made in the past to operate combustors using alternatives to natural gas, including liquid hydrocarbon fuels such as oil and diesel fuel, either alone or in combination with other gaseous fuel components. In order to generate a lean, premixed and pre-vaporized flame using liquid fuels, the fuel must first be vaporized and, if possible, reformed into more combustible and thermally efficient gases that can be mixed with air to create an acceptable fuel vapor prior to ignition in the combustor. Even then, the use of liquid fuels containing higher molecular weight hydrocarbon constituents in combination with other gas fuel elements (including lower weight aliphatic hydrocarbons) has proven to be problematic.
One recognized approach to using higher molecular weight fuels involves the process of reforming the fuels, particularly heavy oils or naphtha, into lighter hydrocarbon components. However, known reformation processes involve complex and expensive process control issues, including potential thermal efficiency losses. For example, gas turbine designs that use oil as one fuel component are vulnerable to high temperature corrosion from contaminants which cannot be readily reformed into more usable fuels. As a result, most gas turbine engines using liquid fuels run on either liquid natural gas (LNG) or very light oils that can be easily broken down into smaller hydrocarbon components and/or vaporized efficiently. Known conversion processes include catalytic steam reforming, autothermal catalytic reforming, catalytic partial oxidation and non-catalytic partial oxidation, each of which has advantages and disadvantages and produce various ratios of hydrogen and carbon monoxide (“synthesis gas”).
Even though the reaction products from known catalyst systems (particularly hydrogen) are very desirable as fuel components, they can potentially cause significant damage to combustor components due to the elevated gas temperatures resulting from the catalytic reaction. That is, the reformed product temperatures often exceed the allowable threshold for materials used to form the piping for the gas turbine. Thus, in order to permit the heated reformats stream to feed directly into the combustor, high temperature fluid transfer materials are required for the downstream piping, which significantly increases system material costs. Additionally, the catalytic reformer must be cooled in some manner to prevent overheating and damage to reformer components which, even with conventional heat exchangers, adds significant complexity and expense to the system.
Given the high temperatures involved in existing reforming processes, the use of fuel reforming catalyst systems to generate additional hydrogen for use in gas turbine engines has been very limited. The known prior art catalyst systems simply do not provide an acceptable method for reforming heavier liquids and/or gas fuel components while effectively controlling and utilizing the exothermic heat of reaction generated by the reforming operation.
Thus, various thermal efficiency issues still exist with known prior art systems. For example, Muenberger U.S. Pat. No. 3,796,547 discloses a heat exchange apparatus using an exothermic catalyst housed within an enclosed cylindrical vessel with one or more heat exchangers embedded within the catalyst bed to assist in controlling the heat generated by the catalytic reaction of the feed stream, with the coolant (typically water) being introduced from an outside source and then removed from the heat exchangers. Muenberger does not contemplate or teach using the treated process stream to impart cooling to the reformed constituents or otherwise maintain a thermally integrated process.
Sederquist U.S. Pat. No. 6,444,179 describes an “autothermal” fuel cell type reformer for converting a fuel and generating free hydrogen via a catalytic reaction using superheated steam. The fuel cell reformer comprises a closed pressure vessel with first and second reactant manifolds, each consisting of a plurality of mixing tubes configured such that the heat generated from the catalytic reaction can be used to generate the superheated steam used in the reaction. Sederquist does not contemplate using the additional heat to treat the fuel source.
Clawson et al, U.S. Pat. No. 6,083,425, illustrates a conventional method for converting a hydrocarbon fuel into hydrogen and carbon dioxide within a “reformer” using an oxygen-rich gas feed and steam introduced into a partial oxidation reaction zone containing a reforming catalyst. Clawson et al do not contemplate using the treated fuel stream to impart cooling to the reformed constituents.
Hokari et al, U.S. Publication No. 2005/0472137 discloses a process for treating heavy oil by mixing the oil with “supercritical” high temperature, high pressure water and an oxidizing agent to oxide vanadium, and then separating out the resulting vanadium oxide. Again, Hokari et al do not use thermal integration of catalyst-generated heat.
Commonly-owned U.S. Pat. No. 5,113,478 describes a liquid fuel vaporizer using a heating plug disposed within a tubular body in which the liquid fuel is vaporized as a result of radiant heat from the combustion chamber and “heat-receiving” fins on the outside of the tubular member when the temperature of the combustor chamber exceeds certain threshold levels.
Thus, a significant need still exists for a reformer system capable of producing substantial quantities of free hydrogen while efficiently using the exothermic heat of reaction to treat liquid and/or “waste gas” components to render them chemically and thermally viable as supplemental fuel components.